Presently, low pressure reservoirs, incapable of producing fluid from the reservoir to the surface naturally, account for over 90% of the hydrocarbon producing wells in the United States. There are various means of pumping fluid from these wells, such as the use of sucker rod pumps, hydraulic pumps, jet pumps, and semi-submersible electric pumps. Most of these low pressure wells produce fluid at too low of a flow rate for the majority of the current art pumps to operate efficiently.
The most common system for producing these low pressure, low flow rate wells is through the use of sucker rod pumping systems. Sucker rod pumping systems include a downhole plunger and cylinder type pump connected to a surface unit commonly referred to as a pump jack via rods, or sucker rods. The present art sucker rod systems have several limits and problems. One problem is that while the stroke length of the pump and the strokes per minute may be controlled via selection of the size of the pump jack, these pumping jacks are expensive and each pump size is adapted for a specific range of flow rates and depth of the reservoir. Once the pump unit is placed it is cost prohibitive to change the pump jack. Another problem with these systems resides within the use of the sucker rods. Sucker rods are metal or fiberglass rods which are connected together to form one continuous string of rods often several thousand feet in length when used in hydrocarbon wells. These rod strings are connected usually via pin and box connections. The process of connecting the rod string when running into the hole or disconnecting the strings when pulling out of the hole is time consuming and costly. Additionally, the length and weight of these rods and the reciprocation of the rods produced by the pump jack results in failure, commonly by parting, of the sucker rod string. Another problem is that the sucker rod string is positioned within a tubular string such as tubing. When the system is operating the rod string commonly contacts the tubular string at several points which results in wear of both the rod string and the tubular string resulting in failure of the well. Some studies have shown that these rod pumping systems fail on the average of once every six months resulting in significant repair and maintenance costs, often making producing the well uneconomical. Failures rates in rod pumping systems greatly increase with the deviation of the well bore from vertical.
There have been attempts to develop a pumping system which utilizes the plunger/cylinder type downhole pump while eliminating the use of sucker rods and the related problems. These prior art rodless pump systems typically include a surface unit, which is connected to a subsurface pump by a fluid conduit such as the tubing string. The surface unit activates the subsurface pump by applying pressure to the fluid in the tubing string to compress a spring means in the subsurface pump and displace a slidable piston to draw fluid from the well into a pump chamber. When the surface unit releases the fluid pressure, a spring mechanism in the subsurface pump will displace the piston and lift the fluid in the pump chamber into the tubing string and to the surface. Such systems are disclosed in U.S. Pat. Nos. 2,058,455; 2,123,139; 2,126,880; and 2,508,609. Although, these prior art systems eliminate the rod string they utilize a compression spring for lifting the produced fluid into the tubing string. These springs severely limit the stroke length and thus flow rate of the pump and also tend to fail due to wear and or the accumulation of "trash" carried into the pump.
Other prior art rodless pumps such as disclosed in U.S. Pat. Nos. 4,297,088 replaces the physical spring with a gas chamber. When pressure is applied to the tubing string, a piston will compress the gas within the chamber and, when the pressure is relieved, the gas will expand to lift fluid into the tubing string. These systems allow for a very long stroke length and thus much higher efficiency, but introduces additional problems. A major problem with these prior art pumps is that unlike sucker rod pumps the rodless pumps do not have a precisely defined stroke length. In these rodless pumps, the stroke length is affected by the length of time the surface unit applies pressure to the fluid in the tubing string on each cycle. It is also affected by the compressibility of the fluid in the tubing string and the amount of ballooning of the tubing that occurs. The stroke length is also influenced by the pressure in the gas chamber, since the pressure in the gas chamber must be sufficient to support the hydrostatic pressure of the entire column of fluid back to the surface at the end of the downstroke, the plunger has enough force being applied to it at the end of the downstroke to cause it to strike the limit stop in the barrel with a severe impact. Also, since the surface unit must be capable of compressing this gas to a much higher pressure on the upstroke and due to the fact that the surface unit will not stop pressuring the tubing at the precise moment to prevent contact, the plunger will impact the limit stop on this end of the stroke. Thus, unlike sucker rod pumps, these pumps are difficult to design in a manner such that the maximum stroke may be utilized without the plunger contacting the barrel at the end of the upstroke and downstroke. This contact severely limits the life of the pumps.
It is thus a desire to have a rodless pump system which overcomes the limitations and problems of the prior art pumps. Wherein the rodless pump is connected to a pressure source via a conduit. In a common oilfield application the pump would be connected to the bottom of a tubing string within the reservoir fluid to be produced. A pressure source such as a hydraulic pump would be connected at the surface to the tubing string so as to selectively apply pressure via fluid in the conduit to the pump, raising the plunger assembly in the pump drawing reservoir fluid into the pump. When pressure via the surface pressure source is released, a gas source in the pump forces the plunger assembly downward in the pump pushing the reservoir fluid in the pump into the tubing and to the surface.
Preferably, the pump includes dampening mechanisms at both the top and bottom of the plunger's stroke so as to reduce metal to metal impact within the pump at the end of the top and bottom of the stroke of the plunger assembly. The dampening mechanism may include but is not limited to elastomer barriers, springs, and dampeners such as discussed further below. Several different configurations may be used singularly or in combination to reduce the metal to metal impact and increase the life of the pump.
The pump assembly may also include a charge valve in fluid connection with the pressure chamber so as to charge the chamber with gas, if the original gas contained within the pump dissipates. The gas chamber may be recharged through the charge valve via a pressurized source which may be run into the hole such as via a wireline.